Methods and compositions for stimulating the production of hydrocarbons from subterranean formations

ABSTRACT

Methods and compositions for stimulating of the production of hydrocarbons (e.g., formation crude oil and/or formation gas) from subterranean formations, and methods of selecting a composition for treating an oil or gas well. In some embodiments, the compositions are emulsions or microemulsions, which may include water, a terpene, and a surfactant.

RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.15/804,114, filed Nov. 6, 2017, which is a continuation of U.S.application Ser. No. 15/249,760 (now U.S. Pat. No. 9,809,741), filedAug. 29, 2016, which is a continuation of U.S. application Ser. No.13/829,495 (now U.S. Pat. No. 9,428,683), filed Mar. 14, 2013, which areincorporated herein by reference in their entirety.

FIELD OF INVENTION

The present invention generally provides methods and compositions forstimulating the production of hydrocarbons (e.g., formation crude oiland/or formation gas) from subterranean formations.

BACKGROUND OF INVENTION

For many years, petroleum has been recovered from subterraneanreservoirs through the use of drilled wells and production equipment.During the production of desirable hydrocarbons, such as crude oil andnatural gas, a number of other naturally occurring substances may alsobe encountered within the subterranean environment. The term“stimulation” generally refers to the treatment of geological formationsto improve the recovery of liquid hydrocarbons (e.g., formation crudeoil and/or formation gas). Common stimulation techniques include wellfracturing and acidizing operations.

Oil and natural gas are found in, and produced from, porous andpermeable subterranean formations. The porosity and permeability of theformation determine its ability to store hydrocarbons, and the facilitywith which the hydrocarbons can be extracted from the formation.Hydraulic fracturing is commonly used to stimulate low permeabilitygeological formations to improve the recovery of hydrocarbons. Theprocess can involve suspending chemical agents in a well-treatment fluid(e.g., fracturing fluid) and injecting the fluid down the wellbore.However, the assortment of chemicals pumped down the well can causedamage to the surrounding formation by entering the reservoir rock andblocking the pore throats. It is known that fluid invasion can have adetrimental effect on gas permeability and can impair well productivity.In addition, fluids may become trapped in the formation due to capillaryend effects in and around the vicinity of the formation fractures.

In efforts to reduce phase trapping, additives have been incorporatedinto well-treatment fluids. Generally, the composition of additivescomprises multi-component chemical substances and compositions thatcontain mutually distributed nanodomains of normally immisciblesolvents, such as water and hydrocarbon-based organic solvents,stabilized by surfactants (e.g., microemulsions). The incorporation ofadditives into well-treatment fluids can increase crude oil or formationgas, for example by reducing capillary pressure and/or minimizingcapillary end effects.

Although a number of additives are known in the art, there is acontinued need for more effective additives for increasing crude oil orformation gas for wellbore remediation, drilling operations, andformation stimulation.

SUMMARY OF INVENTION

Methods and compositions for stimulating the production of hydrocarbons(e.g., formation crude oil and/or formation gas) from subterraneanformations are provided.

In some embodiments, methods of selecting a composition for treating anoil or gas well having a wellbore are provided comprising determiningwhether displacement of residual aqueous treatment fluid by formationcrude oil or displacement of residual aqueous treatment fluid byformation gas is preferentially stimulated for the oil or gas wellhaving a wellbore; and selecting an emulsion or a microemulsion forinjection into the wellbore to increase formation crude oil or formationgas production by the well, wherein the emulsion or the microemulsioncomprises water, a terpene, and a surfactant, the ratio of water toterpene is between about 3:1 and about 1:2; wherein the terpene has aphase inversion temperature greater than 43° C. when displacement ofresidual aqueous treatment fluid by formation crude oil ispreferentially stimulated, or wherein the terpene has a phase inversiontemperature less than 43° C. when displacement of residual aqueoustreatment fluid by formation gas is preferentially stimulated. In someembodiments, the method further comprises injecting the emulsion or themicroemulsion into the wellbore to increase production of formationcrude oil or formation gas by the well.

In some embodiments, methods of treating an oil or gas well having awellbore are provided comprising injecting an emulsion or amicroemulsion into the wellbore of the oil or gas well to stimulatedisplacement of residual aqueous treatment fluid by formation crude oiland increase production of formation crude oil by the well, wherein theemulsion or the microemulsion comprises water, a terpene, and asurfactant; wherein the ratio of water to terpene is between about 3:1and about 1:2; and wherein the terpene has a phase inversion temperaturegreater than 43° C.

In some embodiments, methods of treating an oil or gas well having awellbore are provided comprising injecting an emulsion or amicroemulsion into the wellbore of the oil or gas well to stimulatedisplacement of residual aqueous treatment fluid by formation gas andincrease production of formation gas by the well, wherein the emulsionor the microemulsion comprises water, a terpene, and a surfactant;wherein the ratio of water to terpene is between about 3:1 and about1:2; and wherein the terpene has a phase inversion temperature less than43° C.

In some embodiments, methods of treating an oil or gas well having awellbore are provided comprising using an emulsion or a microemulsion tostimulate displacement of residual aqueous treatment fluid by formationcrude oil or displacement of residual aqueous treatment fluid byformation gas by injecting the emulsion or the microemulsion into thewellbore of the oil or gas well, and increase production of formationcrude oil or formation gas by the well, wherein the emulsion or themicroemulsion comprises water, a terpene, and a surfactant; wherein theratio of water to terpene is between about 10:1 and about 3:1; andwherein the terpene has a phase inversion temperature of greater than43° C.

In some embodiments, methods of treating an oil or gas well having awellbore are provided comprising using an emulsion or a microemulsion tostimulate displacement of residual aqueous treatment fluid by oil ordisplacement of residual aqueous treatment fluid by gas by injecting theemulsion or the microemulsion into the wellbore of the oil or gas well,and increase production of formation crude oil or formation gas by thewell, wherein the emulsion or the microemulsion comprises water, aterpene, and a surfactant; wherein the ratio of water to terpene isbetween about 10:1 and about 3:1; and wherein the terpene has a phaseinversion temperature of less than 43° C.

In some embodiments, an emulsion or a microemulsion for stimulating anoil or gas well is provided comprising an aqueous phase; a surfactant; afreezing point depression agent; and a terpene, wherein the terpene isnopol.

In some embodiments, an emulsion or a microemulsion for stimulating anoil or gas well is provided comprising an aqueous phase; a surfactant; afreezing point depression agent; and a terpene, wherein the terpene iseucalyptol.

Other aspects, embodiments, and features of the invention will becomeapparent from the following detailed description when considered inconjunction with the accompanying drawings. All patent applications andpatents incorporated herein by reference are incorporated by referencein their entirety. In case of conflict, the present specification,including definitions, will control.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings are not intended to be drawn to scale. In thedrawings, each identical or nearly identical component that isillustrated in various figures is represented by a like numeral. Forpurposes of clarity, not every component may be labeled in everydrawing. In the drawings:

FIG. 1 shows an exemplary plot for determining the phase inversiontemperature of a microemulsion, according to some embodiments.

DETAILED DESCRIPTION

The present invention generally relates to methods and well-treatmentcompositions (e.g., emulsions or microemulsions) for stimulating of theproduction of liquid hydrocarbons (e.g., formation crude oil and/orformation gas) from subterranean formations. In some embodiments, thecompositions comprise an emulsion or a microemulsion, as described inmore detail herein. The emulsions or the microemulsions may includewater, a terpene, a surfactant, and optionally a freezing pointdepression agent or other components. In some embodiments, the methodsrelate to stimulating displacement of residual aqueous treatment fluidby formation crude oil or formation gas to increase production of liquidhydrocarbons, as described in more detail below. In some embodiments,methods of selecting an emulsion or a microemulsion comprising a terpeneare provided, wherein the emulsion or the microemulsion is selected soas to increase liquid hydrocarbon production.

As described herein, in some embodiments, the inventors have found thatmicroemulsions or emulsions comprising certain terpenes increase thedisplacement (e.g., flowback) of residual aqueous treatment fluid byliquid hydrocarbons (e.g., crude oil) as compared to other terpenes. Inother embodiments, emulsions or microemulsions comprising certainterpenes increase the displacement of residual aqueous treatment fluidby gaseous hydrocarbons as compared to other terpenes. Laboratory testsmay be conducted, as described herein, to determine the displacement ofresidual aqueous treatment fluid by liquid hydrocarbons and/or gaseoushydrocarbons of an emulsion or a microemulsion

Petroleum is generally recovered from subterranean reservoirs throughthe use of drilled wells and production equipment. Wells are“stimulated” using various treatments (e.g., fracturing, acidizing) ofgeological formations to improve the recovery of liquid hydrocarbons.Oil and natural gas are found in, and produced from, porous andpermeable subterranean formations. Based on techniques known in the art,as well as the preference for the desired product isolated (e.g.,formation crude oil or formation gas), it may be preferential tostimulate either crude oil production or gas production from each well.A well drilled into a subterranean formation may penetrate formationscontaining liquid or gaseous hydrocarbons or both, as well as connatewater or brine. The gas-to-oil ratio is termed the GOR. The operator ofthe well may choose to complete the well in such a way as to produce(for example) predominantly liquid hydrocarbons (crude oil).Alternatively, the operator may be fracturing a tight gas shaleformation containing predominantly gaseous hydrocarbons.

Incorporation of the emulsions or the microemulsions described herein(e.g., comprising water, a terpene, and a surfactant) intowell-treatment fluids (e.g., fracturing fluids) can aid in reducingfluid trapping, for example, by reducing capillary pressure and/orminimizing capillary end effects. In additional, incorporation of theemulsions or the microemulsions described herein into well-treatmentfluids can promote increased flow back of aqueous phases following welltreatment, and thus, increase production of liquid and/or gaseoushydrocarbons. That is, incorporation of an emulsion or a microemulsiondescribed herein can aid in the displacement of residual aqueoustreatment fluid by formation crude oil and/or formation gas. Residualaqueous treatment fluids may include those fluids employed forfracturing, as well as residual aqueous fluids originally present in thewell.

In some embodiments, methods of treating an oil or gas well areprovided. In some embodiments, the methods comprise injecting anemulsion or a microemulsion into the wellbore of the oil or gas well tostimulate displacement of residual aqueous treatment fluid by formationcrude oil or formation gas, and increase production of liquidhydrocarbons by the well.

In some embodiments, methods are provided for selecting a compositionfor treating an oil or gas well. The inventors have discovered thatcertain terpenes are more effective at stimulating displacement ofresidual aqueous treatment fluid by formation crude oil or displacementof residual aqueous treatment fluid by formation gas for the oil or gaswell and that the selection of the terpene may be influenced by theratio of water to terpene in the emulsion or the microemulsion.

In some embodiments, if displacement of residual aqueous treatment fluidby formation crude oil is preferentially stimulated and the emulsion orthe microemulsion comprises water to terpene at a ratio between about3:1 and about 1:2, then the terpene may be selected to have a phaseinversion temperature greater than 43° C., as determined by the methoddescribed herein. Alternatively, if displacement of residual aqueoustreatment fluid by formation gas is preferentially stimulated and theemulsion or the microemulsion comprises water to terpene at a ratiobetween about 3:1 and about 1:2, then the terpene may be selected tohave a phase inversion temperature less than 43° C., as determined bythe method described herein In some embodiments, the ratio of water toterpene is between about 3:1 and about 1:1.5, or between about 2:1 andabout 1:1.5.

In some embodiments, to stimulate displacement of residual aqueoustreatment fluid by formation crude oil, the ratio of water to terpene inthe emulsion or the microemulsion may be between about 3:1 and about1:2, or between about 2:1 and about 1:1.5, and the terpene may beselected to have a phase inversion temperature greater than 43° C., asdetermined by the method described herein. In some embodiments, tostimulate displacement of residual aqueous treatment fluid by formationcrude oil or formation gas and increase production of formation gas thewell, the ratio of water to terpene in the emulsion or the microemulsionmay be between about 3:1 and about 1:2, or between about 2:1 and about1:1.5, and the terpene may be selected to have a phase inversiontemperature less than 43° C., as determined by the method describedherein.

In some embodiments, to stimulate displacement of residual aqueoustreatment fluid by formation crude oil, wherein the ratio of water toterpene in the emulsion or the microemulsion is between about 10:1 andabout 3:1, the terpene may be selected to have a phase inversiontemperature greater than 43° C., as determined by the method describedherein. In some embodiments, to stimulate displacement of residualaqueous treatment fluid by formation gas and increase production offormation gas by the well, wherein the ratio of water to terpene in theemulsion or the microemulsion is between about 10:1 and about 3:1, theterpene may be selected to have a phase inversion temperature less than43° C., as determined by the method described herein. In someembodiments, the ratio of water to terpene is between about 6:1 andabout 5:1.

It should understood, that in embodiments where a microemulsion is saidto be injected into a wellbore, that the microemulsion may be dilutedand/or combined with other liquid component(s) prior to and/or duringinjection. For example, in some embodiments, the microemulsion isdiluted with an aqueous carrier fluid (e.g., water, brine, sea water,fresh water, or a treatment fluid such as a fracturing fluid comprisingpolymers, sand, etc.) prior to and/or during injection into thewellbore. In some embodiments, a composition for injecting into awellbore is provided comprising a microemulsion as described herein andan aqueous carrier fluid, wherein the microemulsion is present in anamount between about 0.1 and about 50 gallons per thousand gallons ofdilution fluid (“gpt”), or between about 0.5 and about 10 gpt, orbetween about 0.5 and about 2 gpt. Generally, dilution of amicroemulsion does not result in the breakdown of the microemulsion.

In some embodiments, emulsions or microemulsion are provided. The termsshould be understood to include emulsions or microemulsions that have awater continuous phase, or that have an oil continuous phase, ormicroemulsions that are bicontinuous.

As used herein, the term “emulsion” is given its ordinary meaning in theart and refers to dispersions of one immiscible liquid in another, inthe form of droplets, with diameters approximately in the range of100-1,000 nanometers. Emulsions may be thermodynamically unstable and/orrequire high shear forces to induce their formation.

As used herein, the term “microemulsion” is given its ordinary meaningin the art and refers to dispersions of one immiscible liquid inanother, in the form of droplets, with diameters approximately in therange of about 10-100 nanometers. Microemulsions are clear ortransparent because they contain particles smaller than the wavelengthof visible light. In addition, microemulsions are thermodynamicallystable and form spontaneously, and thus, differ markedly fromthermodynamically unstable emulsions, which generally depend uponintense mixing energy for their formation. The microemulsion may besingle phased. Microemulsions may be characterized by a variety ofadvantageous properties including, by not limited to, (i) clarity, (ii)very small particle size, (iii) ultra-low interfacial tensions, (iv) theability to combine properties of water and oil in a single homogeneousfluid, (v) shelf stability, and (vi) ease of preparation.

It should be understood, that while much of the description hereinfocuses on microemulsions, this is by no means limiting, and emulsionsmay be employed where appropriate.

In some embodiments, a microemulsion comprises water, a terpene, and asurfactant. In some embodiments, the microemulsion may further compriseaddition components, for example, a freezing point depression agent.Details of each of the components of the microemulsions are described indetail herein. In some embodiments, the components of the microemulsionsare selected so as to reduce or eliminate the hazards of themicroemulsion to the environment and/or the subterranean reservoirs.

In some embodiments, the microemulsion comprises a terpene. Themicroemulsion may comprise a single terpene or a combination of two ormore terpenes. For example, in some embodiments, the terpene comprises afirst type of terpene and a second type of terpene. Terpenes may begenerally classified as monoterpenes (e.g., having two isoprene units),sesquiterpenes (e.g., having 3 isoprene units), diterpenes, or the like.In some embodiments, the terpene is a monoterpene. Monoterpenes may befurther classified as acyclic, monocyclic, and bicyclic [18-20], as wellas whether the monoterpene comprises one or more oxygen atoms (e.g.,alcohol groups, ester groups, carbonyl groups, etc.). In someembodiments, the terpene comprises an alcohol group. Non-limitingexamples of terpenes comprising an alcohol group are linalool, geraniol,nopol, α-terpineol, and menthol. In some embodiments, the terpenecomprises an ether-oxygen, for example, eucalyptol, or a carbonyloxygen, for example, menthone. In some embodiments, the terpene does notcomprise an oxygen atom, for example, d-limonene.

Non-limiting examples of terpenes include linalool, geraniol, nopol,α-terpineol, menthol, eucalyptol, menthone, d-limonene, terpinolene,β-occimene, γ-terpinene, α-pinene, and citronellene. In a particularembodiment, the terpene is selected from the group consisting ofα-terpeneol, α-pinene, nopol, and eucalyptol. In one embodiment, theterpene is nopol. In another embodiment, the terpene is eucalyptol. Insome embodiments, the terpene is not limonene (e.g., d-limonene). Insome embodiments, the emulsion is free of limonene

In some embodiments, the terpene may be classified in terms of its phaseinversion temperature (“PIT”). The term “phase inversion temperature” isgiven its ordinary meaning in the art and refers to the temperaturewhere an oil in water microemulsion inverts to a water in oilmicroemulsion (or vice versa). Those of ordinary skill in the art willbe aware of methods for determining the PIT for a microemulsioncomprising a terpene (e.g., see Strey, Colloid & Polymer Science, 1994.272(8): p. 1005-1019; Kahlweit et al., Angewandte Chemie InternationalEdition in English, 1985. 24(8): p. 654-668). The PIT values describedherein were determined using a 1:1 ratio of terpene (e.g., one or moreterpenes):de-ionized water and varying amounts (e.g., between about 20wt % and about 60 wt %; generally, between 3 and 9 different amounts areemployed) of a 1:1 blend of surfactant comprising linear C₁₂-C₁₅ alcoholethoxylates with on average 7 moles of ethylene oxide (e.g., Neodol25-7):isopropyl alcohol wherein the upper and lower temperatureboundaries of the microemulsion region can be determined and a phasediagram may be generated. Those of ordinary skill in the art willrecognize that such a phase diagram (e.g., a plot of temperature againstsurfactant concentration at a constant oil-to-water ratio) may bereferred to as “fish” diagram or a Kahlweit plot. The temperature at thevertex is the PIT. An exemplary fish diagram indicating the PIT is shownin FIG. 1. PITs for non-limiting examples of terpenes determined usingthis experimental procedure outlined above are given in Table 1.

TABLE 1 Phase inversion temperatures for non- limiting examples ofterpenes. Terpene Phase Inversion Temperature (° C.) Linalool −4Geraniol −0.5 Nopol 2.5 α-Terpineol 4.6 Menthol 16 Eucalyptol 31Menthone 32 d-Limonene 43 Terpinolene 48 β-Occimene 49 γ-Terpinene 49α-Pinene 57 Citronellene 58

In some embodiments, as described in more detail herein, the terpene hasa PIT greater than and/or less than 43° C., as determined by the methoddescribed herein. In some embodiments, the terpene has a PIT greaterthan 43° C., as determined by the method described herein. In someembodiments, the terpene has a PIT less than 43° C., as determined bythe method described herein. In some embodiments, the terpene has a PITgreater than 32° C., as determined by the method described herein. Insome embodiments, the terpene has a PIT less than 32° C., as determinedby the method described herein. In some embodiments, the PIT is betweenabout −10° C. and about 70° C., or between about −4° C. and about 60°C., as determined by the method described herein. In some embodiments,the minimum PIT is −10° C., or −4° C., as determined by the methoddescribed herein. In some embodiments, the maximum PIT is 70° C., or 60°C., as determined by the method described herein.

The terpene may be present in the microemulsion in any suitable amount.In some embodiments, terpene is present in an amount between aboutbetween about 2 wt % and about 60 wt %, or between about 5 wt % andabout 40 wt %, or between about 5 wt % and about 30 wt %, versus thetotal microemulsion composition.

The water to terpene ratio in a microemulsion may be varied, asdescribed herein. In some embodiments, the ratio of water to terpene,along with other parameters of the terpene (e.g., phase inversiontemperature of the terpene) may be varied so that displacement ofresidual aqueous treatment fluid by formation gas and/or formation crudeis preferentially stimulated. In some embodiments, the ratio of water toterpene is between about 3:1 and about 1:2, or between about 2:1 andabout 1:1.5. In other embodiments, the ratio of water to terpene isbetween about 10:1 and about 3:1, or between about 6:1 and about 5:1.

In some embodiments, the microemulsion comprises a surfactant. Themicroemulsion may comprise a single surfactant or a combination of twoor more surfactants. For example, in some embodiments, the surfactantcomprises a first type of surfactant and a second type of surfactant.The term “surfactant,” as used herein, is given its ordinary meaning inthe art and refers to compounds having an amphiphilic structure whichgives them a specific affinity for oil/water-type and water/oil-typeinterfaces which helps the compounds to reduce the free energy of theseinterfaces and to stabilize the dispersed phase of a microemulsion. Theterm surfactant encompasses cationic surfactants, anionic surfactants,amphoteric surfactants, nonionic surfactants, zwitterionic surfactants,and mixtures thereof. In some embodiments, the surfactant is a nonionicsurfactant. Nonionic surfactants generally do not contain any charges.Amphoteric surfactants generally have both positive and negativecharges, however, the net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution. Anionicsurfactants generally possess a net negative charge. Cationicsurfactants generally possess a net positive charge.

Suitable surfactants for use with the compositions and methods describedherein will be known in the art. In some embodiments, the surfactant isan alkyl polyglycol ether, for example, having 2-40 ethylene oxide (EO)units and alkyl groups of 4-20 carbon atoms. In some embodiments, thesurfactant is an alkylaryl polyglycol ether having 2-40 EO units and8-20 carbon atoms in the alkyl and aryl groups. In some embodiments, thesurfactant is an ethylene oxide/propylene oxide (EO/PO) block copolymerhaving 8-40 EO or PO units. In some embodiments, the surfactant is afatty acid polyglycol ester having 6-24 carbon atoms and 2-40 EO units.In some embodiments, the surfactant is a polyglycol ether ofhydroxyl-containing triglycerides (e.g., castor oil). In someembodiments, the surfactant is an alkylpolyglycoside of the generalformula R″—O—Z_(n), where R″ denotes a linear or branched, saturated orunsaturated alkyl group having on average 8-24 carbon atoms and Z_(n)denotes an oligoglycoside group having on average n=1-10 hexose orpentose units or mixtures thereof. In some embodiments, the surfactantis a fatty ester of glycerol, sorbitol, or pentaerythritol. In someembodiments, the surfactant is an amine oxide (e.g.,dodecyldimethylamine oxide). In some embodiments, the surfactant is analkyl sulfate, for example having a chain length of 8-18 carbon atoms,alkyl ether sulfates having 8-18 carbon atoms in the hydrophobic groupand 1-40 ethylene oxide (EO) or propylene oxide (PO) units. In someembodiments, the surfactant is a sulfonate, for example, an alkylsulfonate having 8-18 carbon atoms, an alkylaryl sulfonate having 8-18carbon atoms, an ester or half ester of sulfosuccinic acid withmonohydric alcohols or alkylphenols having 4-15 carbon atoms. In somecases, the alcohol or alkylphenol can also be ethoxylated with 1-40 EOunits. In some embodiments, the surfactant is an alkali metal salt orammonium salt of a carboxylic acid or poly(alkylene glycol) ethercarboxylic acid having 8-20 carbon atoms in the alkyl, aryl, alkaryl oraralkyl group and 1-40 EO or PO units. In some embodiments, thesurfactant is a partial phosphoric ester or the corresponding alkalimetal salt or ammonium salt, e.g. an alkyl and alkaryl phosphate having8-20 carbon atoms in the organic group, an alkylether phosphate oralkarylether phosphate having 8-20 carbon atoms in the alkyl or alkarylgroup and 1-40 EO units. In some embodiments, the surfactant is a saltof primary, secondary, or tertiary fatty amine having 8-24 carbon atomswith acetic acid, sulfuric acid, hydrochloric acid, and phosphoric acid.In some embodiments, the surfactant is a quaternary alkyl- andalkylbenzylammonium salt, whose alkyl groups have 1-24 carbon atoms(e.g., a halide, sulfate, phosphate, acetate, or hydroxide salt). Insome embodiments, the surfactant is an alkylpyridinium, analkylimidazolinium, or an alkyloxazolinium salt whose alkyl chain has upto 18 carbons atoms (e.g., a halide, sulfate, phosphate, acetate, orhydroxide salt). In some embodiments, the surfactant is amphoteric,including sultaines (e.g., cocamidopropyl hydroxysultaine), betaines(e.g., cocamidopropyl betaine), or phosphates (e.g., lecithin).Non-limiting examples of specific surfactants include a linear C₁₂-C₁₅ethoxylated alcohols with 5-12 moles of EO, lauryl alcohol ethoxylatewith 4-8 moles of EO, nonyl phenol ethoxylate with 5-9 moles of EO,octyl phenol ethoxylate with 5-9 moles of EO, tridecyl alcoholethoxylate with 5-9 moles of EO, Pluronic® matrix of EO/PO copolymers,ethoxylated cocoamide with 4-8 moles of EO, ethoxylated coco fatty acidwith 7-11 moles of EO, and cocoamidopropyl amine oxide.

Those of ordinary skill in the art will be aware of methods andtechniques for selecting surfactant for use in the microemulsionsdescribed herein. In some cases, the surfactant(s) are matched to and/oroptimized for the particular oil or solvent in use. In some embodiments,the surfactant(s) are selected by mapping the phase behavior of themicroemulsion and choosing the surfactant(s) that gives the desiredrange of stability. In some cases, the stability of the microemulsionover a wide range of temperatures is targeting as the microemulsion maybe subject to a wide range of temperatures due to the environmentalconditions present at the subterranean formation.

The surfactant may be present in the microemulsion in any suitableamount. In some embodiments, the surfactant is present in an amountbetween about 10 wt % and about 70 wt %, or between about 15 wt % andabout 55 wt % versus the total microemulsion composition, or betweenabout 20 wt % and about 50 wt %, versus the total microemulsioncomposition.

In some embodiments, the microemulsion comprises a freezing pointdepression agent. The microemulsion may comprise a single freezing pointdepression agent or a combination of two or more freezing pointdepression agent. For example, in some embodiments, the freezing pointdepression agent comprises a first type of freezing point depressionagent and a second type of freezing point depression agent. The term“freezing point depression agent” is given its ordinary meaning in theart and refers to a compound which is added to a solution to reduce thefreezing point of the solution. That is, a solution comprising thefreezing point depression agent has a lower freezing point as comparedto an essentially identical solution not comprising the freezing pointdepression agent. Those of ordinary skill in the art will be aware ofsuitable freezing point depression agents for use in the microemulsionsdescribed herein. Non-limiting examples of freezing point depressionagents include primary, secondary, and tertiary alcohols with between 1and 20 carbon atoms. In some embodiments, the alcohol comprises at least2 carbon atoms, alkylene glycols including polyalkylene glycols, andsalts. Non-limiting examples of alcohols include methanol, ethanol,i-propanol, n-propanol, t-butanol, n-butanol, n-pentanol, n-hexanol, and2-ethyl-hexanol. In some embodiments, the freezing point depressionagent is not methanol (e.g., due to toxicity). Non-limiting examples ofalkylene glycols include ethylene glycol (EG), polyethylene glycol(PEG), propylene glycol (PG), and triethylene glycol (TEG). In someembodiments, the freezing point depression agent is not ethylene oxide(e.g., due to toxicity). Non-limiting examples of salts include saltscomprising K, Na, Br, Cr, Cr, Cs, or Bi, for example, halides of thesemetals, including NaCl, KCl, CaCl₂, and MgCl. In some embodiments, thefreezing point depression agent comprises an alcohol and an alkyleneglycol. In some embodiments, the microemulsion comprising the freezingpoint depression agent is stable over a wide range of temperatures, forexample, between about −25° F. to 150° F.

The freezing point depression agent may be present in the microemulsionin any suitable amount. In some embodiments, the freezing pointdepression agent is present in an amount between about 1 wt % and about40 wt %, or between about 3 wt % and about 20 wt %, or between about 8wt % and about 16 wt %, versus the total microemulsion composition.

In some embodiments, the components of the microemulsion and/or theamounts of the components may be selected so that the microemulsion isstable over a wide-range of temperatures. For example, the microemulsionmay exhibit stability between about −40° F. and about 300° F., orbetween about −40° F. and about 150° F. Those of ordinary skill in theart will be aware of methods and techniques for determining the range ofstability of the microemulsion. For example, the lower boundary may bedetermined by the freezing point and the upper boundary may bedetermined by the cloud point and/or using spectroscopy methods.Stability over a wide range of temperatures may be important inembodiments where the microemulsions are being employed in applicationscomprising environments wherein the temperature may vary significantly,or may have extreme highs (e.g., desert) or lows (e.g., artic).

The microemulsions described herein may be formed using methods known tothose of ordinary skill in the art. In some embodiments, the aqueous andnon-aqueous phases may be combined (e.g., the water and the terpene(s)),followed by addition of a surfactant(s) and optionally other components(e.g., freezing point depression agent(s)) and agitation. The strength,type, and length of the agitation may be varied as known in the artdepending on various factors including the components of themicroemulsion, the quantity of the microemulsion, and the resulting typeof microemulsion formed. For example, for small samples, a few secondsof gentle mixing can yield a microemulsion, whereas for larger samples,longer agitation times and/or stronger agitation may be required.Agitation may be provided by any suitable source, for example, a vortexmixer, a stirrer (e.g., magnetic stirrer), etc.

Any suitable method for injecting the microemulsion (e.g., a dilutedmicroemulsion) into a wellbore may be employed. For example, in someembodiments, the microemulsion, optionally diluted, may be injected intoa subterranean formation by injecting it into a well or wellbore in thezone of interest of the formation and thereafter pressurizing it intothe formation for the selected distance. Methods for achieving theplacement of a selected quantity of a mixture in a subterraneanformation are known in the art. The well may be treated with themicroemulsion for a suitable period of time. The microemulsion and/orother fluids may be removed from the well using known techniques,including producing the well.

In some embodiments, experiments may be carried out to determinedisplacement of residual aqueous treatment fluid by formation crude oilor formation gas by a microemulsion (e.g., a diluted microemulsion). Forexample, displacement of residual aqueous treatment fluid by formationcrude oil may be determined using the method described in Example 3and/or displacement of residual aqueous treatment fluid by formation gasmay be determined using the method described in Example 2.

These and other aspects of the present invention will be furtherappreciated upon consideration of the following Examples, which areintended to illustrate certain particular embodiments of the inventionbut are not intended to limit its scope, as defined by the claims.

EXAMPLES Example 1

A series of laboratory tests were conducted to characterize theeffectiveness of a series of microemulsions incorporating a range ofterpenes. For these experiments, samples of a base microemulsion wereprepared in which a detergent range alcohol ethoxylate surfactant wasfirst blended in a 1:1 ratio with isopropyl alcohol. Suitable detergentrange alcohol ethoxylate surfactants include Neodol 25-7 (obtained fromShell Chemical Co.; e.g., a surfactant comprising linear C₁₂-C₁₅ alcoholethoxylates with on average 7 moles of ethylene oxide), or comparablelinear and branched alcohol ethoxylate surfactants available from SASOL,Huntsman or Stepan. The examples in Table 2 were prepared using Neodol25-7. 46 parts by weight of this blend was mixed with 27 parts by weightof terpene and 27 parts by weight of water. Although substantialdifferences in the microemulsion phase behavior of the differentterpenes were observed, this composition was chosen because at thiscomposition, the exemplary terpenes that were tested spontaneouslyformed transparent stable microemulsions with gentle mixing of theingredients. Subsequently, 1-2 gallons per thousand (gpt) dilutions wereprepared and tested.

A transparent low-viscosity mixture that exhibited the characteristicproperties of a microemulsion was prepared using 46% by weight of ablend of Neodol 25-7 and isopropyl alcohol, 27% by weight of water, and27% by weight of technical grade d-limonene. This mixture was identifiedas a microemulsion based on the spontaneous formation with minimalmechanical energy input to form a clear dispersion from an immisciblemixture of water and d-limonene upon addition of an appropriate amountof surfactant and co-solvent. The order of mixing of this and othercompositions described in this example were not necessary, but forconvenience, a procedure was generally followed in which a mixture ofthe surfactant and the isopropyl alcohol was first prepared thencombined that with a mixture of the terpene and water. With smallsamples, in the laboratory, a few seconds of gentle mixing yielded atransparent dispersion.

The non-limiting terpenes used this example were classified by measuringtheir phase inversion temperature (PIT) using methods described in theliterature (e.g., see Strey, Microemulsion microstructure andinterfacial curvature. Colloid & Polymer Science, 1994. 272(8): p.1005-1019; Kahlweit et al., Phase Behavior of Ternary Systems of theType H₂O-Oil-Nonionic Amphiphile (Microemulsions). Angewandte ChemieInternational Edition in English, 1985. 24(8): p. 654-668.). As will beknown in the art, the PIT measured for a given oil or solvent depends onthe surfactant and aqueous phase in which it is measured. In thisexample, a 1:1 mixture of terpene solvent and de-ionized water wascombined with varying amounts of a 1:1 blend of Neodol 25-7 and IPA andthe upper and lower temperature boundaries of the one-phasemicroemulsion region were determined. A phase diagram such as this,plotting temperature against surfactant concentration at a constantoil-to-water ratio is often called a “fish” diagram or a Kahlweit plot.The phase inversion temperature was determined as the point at the“fish-tail” at which the temperature range of one-phase microemulsioncloses to a vertex. In this example, the temperature at the vertex wasselected as the PIT. An exemplary fish diagram indicating the PIT isshown in FIG. 1. For the terpene solvents used in this example, the PITvalues which were measured using this above-described procedure areshown in Table 2. Those terpenes containing alcohol groups (linalool,geraniol, nopol, α-terpineol and menthol), gave PIT values between −4°C. and 16° C. Eucalyptol, containing an ether-oxygen, and menthone,containing a carbonyl oxygen, gave somewhat higher values near 30° C.D-limonene gave 43° C., while other non-oxygen containing terpenes gavevalues between 48-58° C. As described in more detail below, displacementof residual treatment fluid (containing 1-2 gpt of the microemulsionwell treatment) from a sand pack by crude oil or gas was found tocorrelate to the PIT values.

Table 2 shows results for displacement of residual aqueous treatmentfluid by oil and gas for formulations (e.g., using the experimentalprocedures outlined in Examples 3 and 4) using dilutions of themicroemulsions prepared in this example (e.g., the microemulsionscomprising 46 parts of 1:1 Neodol 25-7, 27 parts deionized water, and 27parts terpene solvent). The dilutions were prepared of eachmicroemulsion in 2% KCl, at 2 gpt. The table shows that the terpenesolvents with PIT values higher than 43° C. all give approximately 90%recovery, while those below 43° C. give significantly lower recovery.Table 2 also shows displacement by gas results for the dilutions thatdemonstrates that terpene solvents with PIT values higher than 43° C.give approximately 40% recovery, while those with PIT values below 43°C. give significantly higher recovery.

TABLE 2 PIT values for various terpene solvents (e.g., measured at 1:1water-oil). Displacement results for 2 gpt dilution of microemulsionscomprising 46:27:27 surfactant:water:terpene + isopropanol formulations.Phase Inversion Temperature % displacement of % displacement of Terpene(° C.) brine by crude oil brine by gas Linalool −4 — 81.9 Geraniol −0.569.3 67.8 Nopol 2.5 80.3 58.8 α-Terpineol 4.6 80 92.9 Menthol 16 49.7 —Eucalyptol 31 — 54.6 Menthone 32 79.4 — d-Limonene 43 89.3 45.6Terpinolene 48 90.5 41.8 β-Occimene 49 90.2 44.2 γ-Terpinene 49 89 32.2α-Pinene 57 89.9 38.7 Citronellene 58 88.2 40.5

TABLE 3 Oil and Gas displacement results for α-pinene and α-terpineol asa function of surfactant concentration and solvent-to-water ratio.Formulation % displacement of % displacement of T/S/W* Terpene brine bycrude oil brine by gas 27-46-27 α-terpineol 80 92.9 27-46-27 α-pinene89.9 38.7 21-46-33 α-terpineol 88 83 21-46-33 α-pinene 87 46 11-46-43α-terpineol 88.5 80 11-46-43 α-pinene 96 47 15-56-28 α-terpineol 87.8 8515-56-28 α-pinene 88.6 52 *T/S/W stands for terpene weight %/1:1surfactant-IPA weight %/deionized water wt %

The results shown in Table 3 demonstrate that at a 1:1 ratio of terpeneto water, and 46 weight % surfactant-IPA, the high PIT α-pineneperformed better on oil displacement and much poorer on gas displacementthan the low PIT α-terpineol. As the terpene-to-water ratio decreasesfrom 27-27 to 21-33 to 11-43, the difference in oil displacementperformance decreased, then increased again at the lower level. Highersurfactant levels did not substantially increase or decrease thedisplacement (which may suggest that the microemulsion is performingdifferently than a surfactant package lacking the terpene solvent). Thedisplacement by gas was better for the low PIT α-terpineol than for thehigh PIT α-pinene.

Example 2

Microemulsions were prepared having the following formulation, whereinthe terpene was varied as indicated in Table 4. The water to terpeneratio was about 5.5:1.

Microemulsion Formulation:

Water 27.35 wt % Ethoxylated alcohol surfactant 52.5 wt % 2-propanol8.75 wt % Triethylene Glycol 3 wt % Propylene Glycol 3.3 wt %Ethoxylated castor oil 0.1 wt % Terpene 5 wt %

1 gallon per thousand dilutions were prepared of each microemulsion in2% KCl. The dilutions were then employed to determine the displacementof brine by oil and gas (e.g., using the experimental proceduresoutlined in Examples 3 and 4). The results are given in Table 4.

TABLE 4 Brine displacement by oil and gas Effectiveness of brineEffectiveness of brine Terpene displacement by gas (%) displacement byoil (%) d-limonene 79 64 α-terpineol 90 88 α-pinene 86 87 geraniol 87 89linalool 88 87 nopol 89 88 turpentine 83 76 menthol 82 90 eucalyptol 7790 terpinolene 79 72 β-ocimene 71 68 λ-terpinene 74 60 citronellene 7388

Example 3

This example described a non-limiting experiment for determiningdisplacement of residual aqueous treatment fluid by formation crude oil.A 25 cm long, 2.5 cm diameter capped glass chromatography column waspacked with 77 grams of 100 mesh sand. The column was left open on oneend and a PTFE insert containing a recessed bottom, 3.2 mm diameteroutlet, and nipple was placed into the other end. Prior to placing theinsert into the column, a 3 cm diameter filter paper disc (Whatman, #40)was pressed firmly into the recessed bottom of the insert to preventleakage of 100 mesh sand. A 2″ piece of vinyl tubing was placed onto thenipple of the insert and a clamp was fixed in place on the tubing priorto packing. The columns were gravity-packed by pouring approximately 25grams of the diluted microemulsions (e.g., the microemulsions describedin Examples 1 or 2, and diluted with 2% KCl, e.g., to about 2 gpt, orabout 1 gpt) into the column followed by a slow, continuous addition ofsand. After the last portion of sand had been added and was allowed tosettle, the excess of brine was removed from the column so that thelevel of liquid exactly matched the level of sand. Pore volume in thepacked column was calculated as the difference in mass of fluid prior tocolumn packing and after the column had been packed. Three additionalpore volumes of brine were passed through the column. After the lastpore volume was passed, the level of brine was adjusted exactly to thelevel of sand bed. Light condensate oil was then added on the top ofsand bed to form the 5 cm oil column above the bed. Additional oil wasplaced into a separatory funnel with a side arm open to an atmosphere.Once the setup was assembled, the clamp was released from the tubing,and timer was started. Throughout the experiment the level of oil wasmonitored and kept constant at a 5 cm mark above the bed. Oil was addedfrom the separatory funnel as necessary, to ensure this constant levelof head in the column. Portions of effluent coming from the column werecollected into plastic beakers over a measured time intervals. Theamount of fluid was monitored. When both brine and oil were producedfrom the column, they were separated with a syringe and weighedseparately. The experiment was conducted for 3 hours at which thesteady-state conditions were typically reached. The cumulative % oraqueous fluid displaced from the column over 120 minute time period, andthe steady-state mass flow rate of oil at t=120 min through the columnwere determined.

Example 4

This example described a non-limiting experiment for determiningdisplacement of residual aqueous treatment fluid by formation gas. A 51cm long, 2.5 cm inner-diameter capped glass chromatography column wasfilled with approximately 410±20 g of 20/40 mesh Ottawa sand and thediluted microemulsions (e.g., the microemulsions described in Examples 1or 2, and diluted with 2% KCl, e.g., to about 2 gpt, or about 1 gpt) Toensure uniform packing, small amounts of proppant were interchanged withsmall volumes of liquid. Periodically the mixture in the column washomogenized with the help of an electrical hand massager, in order toremove possible air pockets. Sand and brine were added to completelyfill the column to the level of the upper cap. The exact amounts offluid and sand placed in the column were determined in each experiment.The column was oriented vertically and was connected at the bottom to anitrogen cylinder via a gas flow controller pre-set at a flow rate of 60cm³/min. The valve at the bottom was slowly opened and liquid exitingthe column at the top was collected into a tarred jar placed on abalance. Mass of collected fluid was recorded as a function of time by acomputer running a data logging software. The experiments were conducteduntil no more brine could be displaced from the column. The total % offluid recovered was then calculated.

Example 5

This examples describes a general preparation method for the productionof diluted microemulsion. The microemulsions were prepared in thelaboratory by mixing the ingredients listed in specific examples. Allingredients are commercially available materials. In some embodiments,the components were mixed together in the orderwater-alcohol-surfactant-citrus terpene solvent, but other order ofaddition may also be employed. The mixtures were then agitated on amagnetic stirrer for 5-10 minutes. The microemulsions were then dilutedto concentrations of 1 or 2 gallons per 1000 gallons with 2% KCl brineand these diluted fluids were used in displacement experiments describedin Examples 3 and 4.

It will be evident to one skilled in the art that the present disclosureis not limited to the foregoing illustrative examples, and that it canbe embodied in other specific forms without departing from the essentialattributes thereof. It is therefore desired that the examples beconsidered in all respects as illustrative and not restrictive,reference being made to the appended claims, rather than to theforegoing examples, and all changes which come within the meaning andrange of equivalency of the claims are therefore intended to be embracedtherein.

While several embodiments of the present invention have been describedand illustrated herein, those of ordinary skill in the art will readilyenvision a variety of other means and/or structures for performing thefunctions and/or obtaining the results and/or one or more of theadvantages described herein, and each of such variations and/ormodifications is deemed to be within the scope of the present invention.More generally, those skilled in the art will readily appreciate thatall parameters, dimensions, materials, and configurations describedherein are meant to be exemplary and that the actual parameters,dimensions, materials, and/or configurations will depend upon thespecific application or applications for which the teachings of thepresent invention is/are used. Those skilled in the art will recognize,or be able to ascertain using no more than routine experimentation, manyequivalents to the specific embodiments of the invention describedherein. It is, therefore, to be understood that the foregoingembodiments are presented by way of example only and that, within thescope of the appended claims and equivalents thereto, the invention maybe practiced otherwise than as specifically described and claimed. Thepresent invention is directed to each individual feature, system,article, material, kit, and/or method described herein. In addition, anycombination of two or more such features, systems, articles, materials,kits, and/or methods, if such features, systems, articles, materials,kits, and/or methods are not mutually inconsistent, is included withinthe scope of the present invention.

The indefinite articles “a” and “an,” as used herein in thespecification and in the claims, unless clearly indicated to thecontrary, should be understood to mean “at least one.”

The phrase “and/or,” as used herein in the specification and in theclaims, should be understood to mean “either or both” of the elements soconjoined, i.e., elements that are conjunctively present in some casesand disjunctively present in other cases. Other elements may optionallybe present other than the elements specifically identified by the“and/or” clause, whether related or unrelated to those elementsspecifically identified unless clearly indicated to the contrary. Thus,as a non-limiting example, a reference to “A and/or B,” when used inconjunction with open-ended language such as “comprising” can refer, inone embodiment, to A without B (optionally including elements other thanB); in another embodiment, to B without A (optionally including elementsother than A); in yet another embodiment, to both A and B (optionallyincluding other elements); etc.

As used herein in the specification and in the claims, “or” should beunderstood to have the same meaning as “and/or” as defined above. Forexample, when separating items in a list, “or” or “and/or” shall beinterpreted as being inclusive, i.e., the inclusion of at least one, butalso including more than one, of a number or list of elements, and,optionally, additional unlisted items. Only terms clearly indicated tothe contrary, such as “only one of” or “exactly one of,” or, when usedin the claims, “consisting of,” will refer to the inclusion of exactlyone element or a list of elements. In general, the term “or” as usedherein shall only be interpreted as indicating exclusive alternatives(i.e. “one or the other but not both”) when preceded by terms ofexclusivity, such as “either,” “one of,” “only one of,” or “exactly oneof.” “Consisting essentially of,” when used in the claims, shall haveits ordinary meaning as used in the field of patent law.

As used herein in the specification and in the claims, the phrase “atleast one,” in reference to a list of one or more elements, should beunderstood to mean at least one element selected from any one or more ofthe elements in the list of elements, but not necessarily including atleast one of each and every element specifically listed within the listof elements and not excluding any combinations of elements in the listof elements. This definition also allows that elements may optionally bepresent other than the elements specifically identified within the listof elements to which the phrase “at least one” refers, whether relatedor unrelated to those elements specifically identified. Thus, as anon-limiting example, “at least one of A and B” (or, equivalently, “atleast one of A or B,” or, equivalently “at least one of A and/or B”) canrefer, in one embodiment, to at least one, optionally including morethan one, A, with no B present (and optionally including elements otherthan B); in another embodiment, to at least one, optionally includingmore than one, B, with no A present (and optionally including elementsother than A); in yet another embodiment, to at least one, optionallyincluding more than one, A, and at least one, optionally including morethan one, B (and optionally including other elements); etc.

In the claims, as well as in the specification above, all transitionalphrases such as “comprising,” “including,” “carrying,” “having,”“containing,” “involving,” “holding,” and the like are to be understoodto be open-ended, i.e., to mean including but not limited to. Only thetransitional phrases “consisting of” and “consisting essentially of”shall be closed or semi-closed transitional phrases, respectively, asset forth in the United States Patent Office Manual of Patent ExaminingProcedures, Section 2111.03.

What is claimed is:
 1. A method of treating a formation crude oil wellhaving a wellbore comprising: injecting an emulsion or a microemulsioninto the wellbore of the formation crude oil well to stimulatedisplacement of residual aqueous treatment fluid by formation crude oiland increase production of formation crude oil by the well, wherein theemulsion or the microemulsion comprises water, a terpene, and asurfactant; and wherein the terpene has a phase inversion temperaturegreater than or equal to 43° C.
 2. A method of treating a formation gaswell having a wellbore comprising: injecting an emulsion or amicroemulsion into the wellbore of the formation gas well to stimulatedisplacement of residual aqueous treatment fluid by formation gas andincrease production of formation gas by the well, wherein the emulsionor the microemulsion comprises water, a terpene, and a surfactant; andwherein the terpene has a phase inversion temperature less than 43° C.3. The method of claim 1, wherein the terpene is selected from the groupconsisting of d-limonene, terpinolene, β-occimene, γ-terpinene,α-pinene, and citronellene.
 4. The method of claim 2, wherein theterpene is selected from the group consisting of linalool, geraniol,nopol, α-terpineol, menthol, eucalyptol and menthone.
 5. The method ofclaim 1, wherein the emulsion or the microemulsion comprising a firsttype of terpene and a second type of terpene.
 6. The method of claim 1,wherein the emulsion or the microemulsion is diluted with an aqueousfluid prior to injection to the wellbore.
 7. The method of claim 1,wherein the emulsion or the microemulsion further comprises a freezingpoint depression agent.
 8. The method of claim 1, wherein the freezingpoint depression agent comprises an alkylene glycol, an alcohol, and/ora salt.
 9. The method of claim 1, wherein the surfactant is selectedfrom the group consisting of nonionic surfactants, anionic surfactants,cationic surfactants and zwitterionic surfactants.
 10. A method oftreating a formation crude oil well having a wellbore comprising: usingan emulsion or a microemulsion to stimulate displacement of residualaqueous treatment fluid by formation crude oil by injecting the emulsionor the microemulsion into the wellbore of the formation crude oil well,and increase production of formation crude oil by the well, wherein theemulsion or the microemulsion comprises water, a terpene, and asurfactant; and wherein the terpene has a phase inversion temperature ofgreater than or equal to 43° C.
 11. A method of treating a formation gaswell having a wellbore comprising: using an emulsion or a microemulsionto stimulate displacement of residual aqueous treatment fluid by gas byinjecting the emulsion or the microemulsion into the wellbore of theformation gas well, and increase production of formation gas by thewell, wherein the emulsion or the microemulsion comprises water, aterpene, and a surfactant; and wherein the terpene has a phase inversiontemperature of less than 43° C.
 12. The method of claim 10, wherein theterpene is selected from the group consisting of d-limonene,terpinolene, β-occimene, γ-terpinene, α-pinene, and citronellene. 13.The method of claim 11, wherein the terpene is selected from the groupconsisting of linalool, geraniol, nopol, α-terpineol, menthol,eucalyptol and menthone.
 14. The method of claim 10, wherein theemulsion or the microemulsion comprising a first type of terpene and asecond type of terpene.
 15. The method of claim 10, wherein the emulsionor the microemulsion is diluted with an aqueous fluid prior to injectionto the wellbore.
 16. The method of claim 10, wherein the emulsion or themicroemulsion further comprises a freezing point depression agent. 17.The method of claim 10, wherein the freezing point depression agentcomprises an alkylene glycol, an alcohol, and/or a salt.
 18. The methodof claim 10, wherein the surfactant is selected from the groupconsisting of nonionic surfactants, anionic surfactants, cationicsurfactants and zwitterionic surfactants.